Methods and Apparatus for Characterization of Petroleum Fluids Contaminated with Drilling Mud

Abstract

A method and system for characterizing formation fluids contaminated with drilling mud that compensates for the presence of such drilling mud. The operations that characterize formation fluids contaminated with drilling mud can be carried out in real-time. The operations also characterize a wide array of fluid properties of petroleum samples contaminated with drilling mud in a manner that compensates for the presence of drilling mud. The operations characterize the viscosity and density of petroleum samples contaminated with drilling mud at formation conditions in a manner that compensates for differences between formation conditions and flowline measurement conditions. The operations also derive live fluid density unaffected by contamination of mud filtrate based on a scaling coefficient dependent on measured gas-oil ratio of the formation fluid. This scale factor accounts for excess volume created during mixing processes, which increases the accuracy of characterizations for high gas-oil ratio samples, especially gas condensate.

Description

BACKGROUND OF THE INVENTION[0001]1. Field of the Invention[0002]The present invention relates to methods and apparatus for characterizing petroleum fluid extracted from a hydrocarbon bearing geological formation.[0003]2. Description of Related Art[0004]Petroleum consists of a complex mixture of hydrocarbons of various molecular weights, plus other organic compounds. The exact molecular composition of petroleum varies widely from formation to formation. The proportion of hydrocarbons in the mixture is highly variable and ranges from as much as 97 percent by weight in the lighter oils to as little as 50 percent in the heavier oils and bitumens. The hydrocarbons in petroleum are mostly alkanes (linear or branched), cycloalkanes, aromatic hydrocarbons, or more complicated chemicals like asphaltenes. The other organic compounds in petroleum typically contain carbon dioxide (CO2), nitrogen, oxygen, and sulfur, and trace amounts of metals such as iron, nickel, copper, and vanadium.[0005]Th...

AI Technical Summary

Benefits of technology

The present invention provides a method and system for characterizing the fluid properties of petroleum samples contaminated with drilling mud in a real-time manner, compensating for the presence of drilling mud and accounting for excess volume created during mixing processes. This allows for accurate characterization of the formation fluid at the location where it is sampled, without the need for sampling and analysis of formation fluid at another location within the borehole. The method and system can measure various properties of the formation fluid, such as temperature, pressure, live fluid density, live fluid viscosity, gas-oil ratio, API gravity, oil formation volume factor, and live fluid density unaffected by contamination of mud filtrate. The invention provides a more efficient and accurate way to characterize the fluid properties of petroleum samples.

Problems solved by technology

Difficulties in accurately estimating the properties of petroleum fluid arise from the fact that the petroleum fluid samples captured by the borehole sampling and analysis tool are likely contaminated with drilling mud.

This leads to “invasion” of mud filtrate into the formation fluids and the buildup of mudcake on the borehole wall.

When samples are taken, the samples are contaminated with the emulsified mud filtrate and even a small quantity of such mud filtrate in a sample can alter the properties of the fluid sample as measured by the tool.

When samples are taken, the samples are contaminated with the mud filtrate and even a small quantity of such mud filtrate in a sample can alter the properties of the fluid sample as measured by the tool.

Such techniques have several limitations, including the generation of a limited data set (e.g., mud filtrate fraction, GOR) that characterizes properties of the formation fluid in a real-time manner.

Instead, other fluid properties of interest can be derived with significant delay, which typically results from a time period required to allow non-contaminated petroleum fluid to be sampled and analyzed by the tool.

However, this method has several limitations.

First, it requires computational analysis of a one-dimensional column of measurements of density, viscosity, volume fraction of water, and volume fraction of mud filtrate over a number of samples that cannot be applied in real-time.

Second, the method employs mixing rules that ignore excess volume created during mixing processes and cannot generate accurate fluid properties for high GOR systems, especially gas condensate.

Third, the method usually calculates much higher density of oil-based mud than the actual experimental value.

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